During drilling operations, drilling fluid or drilling mud, is pumped down the drill string in the wellbore using what are known as mud pumps. The drilling fluid jets out of the drill bit and cleans the bottom of the hole. The drilling fluid moves back up the wellbore in the annular space between the drill sting and the side of the wellbore, flushing cuttings and debris to the surface. The returning drilling fluid provides hydrostatic pressure to promote the prevention of formation fluids from entering into the wellbore. Drilling fluids are also typically viscous or thixotropic to aid in the suspension of cuttings in the wellbore, both during drilling and during interruptions to drilling.
The mixture of drilling fluid, formation fluids, cuttings and debris travelling back up the wellbore to the surface is referred to as the ‘wellbore returns’ or ‘drilling returns’. The wellbore returns may also contain dissolved gas which moves from the surrounding formation being drilled into the drilling fluid in the annulus.
Upon arrival at the surface, a series of valves and pipes are utilized to controllably direct the wellbore returns to either a mud/gas separator or to a de-gasser. A separator typically comprises a cylindrical or spherical vessel and can be either horizontal or vertical. It is used to separate gas from the drilling fluid and gas mixture. In the separator, the mixture is usually passed over a series of baffles designed to separate gas and mud. Liberated free gas is moved to a flare line and the mud is discharged to a shale shaker and to a mud tank. A de-gasser is used when the gas content of the drilling fluid is relatively lower and it operates on much the same principles as the separator. A vacuum is applied to the fluid as it is passed over the baffles to increase surface area, thereby promoting the liberation of dissolved gas.
During drilling operations, it is important to maintain constant down-hole hydrostatic pressure to prevent formation fluids from entering into the wellbore as mentioned above. This can be challenging due to shifting wellbore conditions and interruptions to drilling operations, such as tripping pipe. To maintain down-hole hydrostatic pressure, conventional drilling operations utilize one or more chokes at the well head. The primary role of the choke is to regulate the flow of wellbore returns from the well head. The choke comprises an adjustable orifice that can be opened or closed to control the flow rate of the wellbore returns, which in turn regulates down-hole pressure. There are both fixed and adjustable chokes, the latter being more conducive to enabling the fluid flow and pressure parameters to be adjusted to suit process and production requirements. However, the chokes, whether fixed or adjustable, are prone to wear, erosion and becoming clogged with cuttings and debris. Further, the chokes do not accurately measure wellbore return volume.
There is a need in the art for an apparatus and a method of controlling wellbore returns to regulate down-hole hydrostatic pressure that may mitigate the problems of existing choke devices, or provide an alternative to existing choke devices.